Method, system, and composition for producing oil

ABSTRACT

A method, system, and composition for producing oil from a formation utilizing an oil recovery formulation comprising a surfactant, an ammonia liquid, an alkali metal carbonate or bicarbonate, a polymer, and water are provided.

This application claims priority from U.S. Provisional Application Ser.No. 61/753,261 filed Jan. 16, 2013, which is hereby incorporated byreference in its entirety.

FIELD OF THE INVENTION

The present invention is directed to a method for producing oil from aformation, in particular, the present invention is directed to a methodof enhanced oil recovery from a formation.

BACKGROUND OF THE INVENTION

In the recovery of oil from a subterranean formation, it is possible torecover only a portion of the oil in the formation using primaryrecovery methods utilizing the natural formation pressure to produce theoil. A portion of the oil that cannot be produced from the formationusing primary recovery methods may be produced by improved or enhancedoil recovery (EOR) methods.

One enhanced oil recovery method utilizes an alkaline-surfactant-polymer(“ASP”) flood in an oil-bearing formation to increase the amount of oilrecovered from the formation. An aqueous dispersion of an alkalinecomponent, a surfactant, and a polymer is injected into an oil-bearingformation to increase recovery of oil from the formation, either afterprimary recovery or after a secondary recovery waterflood. The ASP floodenhances recovery of oil from the formation by lowering interfacialtension between oil and water phases in the formation, therebymobilizing the oil for production. Interfacial tension between the oiland water phases in the formation is reduced by the surfactant of theASP flood and by the formation of soaps by alkali interaction with acidsin the oil. The polymer increases the viscosity of the ASP fluid,typically to the same order of magnitude as the oil in the formation, sothe mobilized oil may be forced through the formation for production bythe ASP flood.

Use of ASP enhanced oil recovery to recover oil from subsea oil-bearingformations may be constrained by the amount of space available on anoffshore oil recovery platform and by the weight limitations of theplatform. Storage facilities must be provided for the polymer, thesurfactant, and for the alkaline component. In some instances theoffshore platform space and weight limitations preclude the use of ASPenhanced oil recovery since there is not enough room to store all of thecomponents of the ASP flood on the platform or the weight of thecomponents of the ASP flood is prohibitive for use on an offshore oilrecovery platform.

Alkalis most commonly used as the alkaline component in ASP EORprocesses include alkali hydroxides and alkali carbonates, and the mostcommon alkaline component utilized in an ASP EOR process is sodiumcarbonate. Offshore oil recovery platform limitations on space andweight may render an alkali carbonate ASP enhanced oil recovery processuntenable for recovering oil from a subsea formation due to therelatively large storage space required for the alkali carbonatestorage, the large space required for mixing facilities, and therelatively heavy weight of the alkali carbonate solution.

Liquid ammonia may be utilized in place of an alkali carbonate or analkali hydroxide as the alkaline component of an ASP EOR process toreduce the space requirements of a system for conducting the ASP EORprocess. Anhydrous liquid ammonia yields 6.2 times the alkalinity of anequivalent weight amount of sodium carbonate, so the weight requirementof the alkaline component of an ASP flood utilizing anhydrous liquidammonia may be reduced by 6.2 times relative to sodium carbonate whileproviding the same relative alkalinity. Less space and weight,therefore, are required to store the ammonia alkaline component relativeto alkali carbonates or alkali hydroxides since less of the ammoniaalkaline component may be used to provide equivalent levels ofalkalinity. On an offshore platform used for recovery of oil from asubsea oil-bearing formation, space and weight savings provided bysubstituting liquid ammonia for commonly used alkali carbonates may bethe determining factor of the feasibility of using an ASP EOR process onthe platform and in the formation.

Use of ammonia as the alkaline component in an ASP EOR process andsystem, however, is limited to utilization with calcium tolerantsurfactants. Calcium ions present in the oil and water of the formationand attached to formation surfaces are not precipitated when ammonia isused as the alkaline component of an ASP EOR flood since calciumhydroxide, the calcium precipitate formed when utilizing liquid ammoniaas the alkali in an ASP EOR process, will only precipitate at Ca²⁺concentrations above 8.8% at 25° C.—above the Ca²⁺ concentration in mostoil-bearing formations. Therefore, only calcium-tolerantsurfactants—those surfactants that are not precipitated in the presenceof significant quantities of calcium cations—may be utilized in ASR EORprocess having ammonia as the alkaline component without substantialloss of surfactant to calcium precipitation. The most commerciallypractical calcium-tolerant surfactants useful in an ASP EOR process,however, are the ethylene oxide sulfate, propylene oxide sulfate, andethylene oxide-propylene oxide sulfate surfactants that hydrolyze at anunacceptable rate above 60° C. Therefore, ASP EOR processes utilizingammonia as the alkaline component are not particularly commerciallypractical in formations having significant concentrations of calciumions therein and a formation temperature of at least 60° C., and ASP EORprocesses in offshore formations having these characteristics may becommercially impractical.

Improvements to existing ASP enhanced oil recovery methods,compositions, and systems are desirable. In particular, methods,compositions, and systems effective to further enable utilization ofASP-based enhanced oil recovery in subsea oil-bearing formations havingsignificant concentrations of calcium ions and formation temperatures ofat least 50° C. or at least 60° C. are desirable.

SUMMARY OF THE INVENTION

In one aspect, the invention is directed to a process for recovering oilfrom an oil-bearing formation, comprising:

mixing a surfactant, water, a polymer, an alkali metal carbonate, andammonia liquid comprising at most 10 wt. % water to form an oil recoveryformulation;

introducing the oil recovery formulation into the oil-bearing formation;

contacting the oil recovery formulation with oil in the oil-bearingformation; and

producing oil from the oil-bearing formation after introduction of theoil recovery formulation into the oil-bearing formation.

In another aspect, the invention is directed to a composition comprisinga surfactant, a polymer, an alkali metal carbonate, ammonia, and water.

In another aspect, the invention is directed to a system, comprising:

a surfactant;

a polymer;

an ammonia liquid comprising at most 10 wt. % water;

an alkali metal carbonate;

water;

an oil-bearing formation;

a mechanism for introducing the surfactant, the polymer, the alkalimetal carbonate; the ammonia liquid, and the water into the oil-bearingformation; and

a mechanism for producing oil from the oil-bearing formation subsequentto introduction of the surfactant, the polymer, the alkali metalcarbonate; the ammonia liquid, and the water into the oil-bearingformation.

In another aspect, the present invention is directed to a process forrecovering oil from an oil-bearing formation, comprising:

introducing a surfactant, water, a polymer, an alkali metal carbonate,and an ammonia liquid containing at most 10 wt. % water into theoil-bearing formation;

mixing the surfactant, water, polymer, the alkali metal carbonate, andammonia liquid in the oil-bearing formation to form an oil recoveryformulation;

contacting the oil recovery formulation with oil in the oil-bearingformation; and

producing oil from the oil bearing-formation after introduction of thesurfactant, water, polymer, alkali metal carbonate, and ammonia liquidinto the oil-bearing formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an illustration of an oil production system in accordance withthe present invention that may be utilized to recover oil by a processin accordance with the present invention.

FIG. 2 is an illustration of an oil production system in accordance withthe present invention that may be utilized to recover oil by a processin accordance with the present invention.

FIG. 3 is a diagram of a well pattern for production of oil inaccordance with a system and process of the present invention.

FIG. 4 is a diagram of a well pattern for production of oil inaccordance with a system and process of the present invention.

FIG. 5 is a photograph of equilibrated mixtures of aqueous sodiumcarbonate/surfactant solutions with oil at different brineconcentrations.

FIG. 6 is a photograph of equilibrated mixtures of aqueous ammoniumhydroxide/surfactant solutions with oil at different brineconcentrations.

FIG. 7 is a photograph of equilibrated mixtures of aqueous ammoniumhydroxide/surfactant solution with oil at different brine concentrationsin the presence of CaCl₂.

FIG. 8 is a photograph of equilibrated mixtures of an aqueous sodiumcarbonate/surfactant solution with oil, an aqueous ammoniumhydroxide/surfactant solution with oil, and an aqueous ammoniumhydroxide/sodium carbonate/surfactant solution with oil at differentbrine concentrations in the presence of CaCl₂.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to a method and system for enhancedoil recovery from an oil-bearing formation utilizing a surfactant,water, a polymer, an alkali metal carbonate or bicarbonate, an ammonialiquid comprising at most 10 wt. % water, and a composition comprising asurfactant, a polymer, an alkali metal carbonate or bicarbonate,ammonia, and water. The surfactant, water, polymer, alkali metalcarbonate or bicarbonate, and ammonia liquid may be mixed together toform an oil recovery formulation for use in the enhanced oil recoveryprocess. The surfactant, alkali metal carbonate or bicarbonate, and theammonia may mobilize the oil in the formation by reducing interfacialtension between oil and water in the formation, the polymer may providea viscosity sufficient to drive the mobilized oil through the formationfor production from the formation, and the alkali metal carbonate orbicarbonate may promote the precipitation of calcium and magnesium inthe formation thereby inhibiting calcium and magnesium inducedprecipitation of the surfactant.

Use of ammonia is favorable for reducing space and weight requirementsof an ASP EOR process relative to conventionally used alkali metalcarbonates. For example, anhydrous liquid ammonia yields 6.2 times thealkalinity of an equivalent weight amount of sodium carbonate, so theweight requirement of the alkali component of an ASP flood systemutilizing anhydrous liquid ammonia may be reduced by 6.2 times relativeto sodium carbonate while providing the same relative alkalinity. Lessspace and weight, therefore, are required to store the ammonia alkalicomponent of the ASP flood system of the present invention relative toconventionally used alkali-carbonate alkali components since less mustbe used to provide equivalent levels of alkalinity. On an offshoreplatform used for recovery of oil from a subsea oil-bearing formation,space and weight savings provided by substituting liquid ammonia forconventionally used alkali components may be the determining factor ofthe feasibility of using an ASP EOR process on the platform.

Sufficient alkali metal carbonate or bicarbonate may be included in theASP mixture to precipitate calcium encountered in the formation as theASP slug moves through the formation, permitting the use of commerciallypractical surfactants in the ASP mixture that are stable at formationtemperatures above 60° C. but are susceptible to precipitation in thepresence of calcium. Preferably, significantly less alkali metalcarbonate or bicarbonate is provided in the ASP mixture utilized in theprocess and system of the present invention than in a conventional ASPflood that utilizes an alkali metal carbonate or bicarbonate as the onlyor primary alkaline component, thereby realizing the space and weightsavings provided by using ammonia as an alkaline component of the ASPmixture while enabling the use of calcium and magnesium intolerantsurfactants in the ASP mixture.

The oil recovery formulation composition of the present invention thatmay be used in the method or system of the present invention iscomprised of a surfactant, a polymer, an alkali metal carbonate orbicarbonate, ammonia, and water. The water may be fresh water or a brinesolution. The water may have a total dissolved solids (TDS) content offrom 100 ppm to 200000 ppm. The water may be provided from a watersource, where the water source may be a fresh water source having a TDScontent of less than 10000 ppm selected from the group consisting of ariver, a lake, a fresh water sea, an aquifier, and formation waterhaving a TDS content of less than 10000 ppm, or the water source may bea saline water source having a TDS content of 10000 ppm or greaterselected from the group consisting of seawater, estuarine water,brackish water, an aquifer, a brine solution provided by processing asaline water source, and formation water having a TDS content of 10000ppm or greater.

When the ASP EOR process utilizing the oil recovery formulation isconducted offshore to recover oil from a subsea oil-bearing formation,the water may be seawater treated to reduce the salinity of the seawaterto a desired TDS content. The salinity of the seawater may be reduced byconventional desalination processes, for example, by passing theseawater through one or more nanofiltration, reverse osmosis, and/orforward osmosis membranes or an ion exchange material.

The TDS content of the oil recovery formulation water may be adjusted tooptimize the salinity of the water for the production of a middle phase,type III, microemulsion of the oil recovery formulation in combinationwith oil and formation water in the formation and thereby minimizeinterfacial tension between oil and water in the formation to maximizemobilization, and therefore, production, of the oil from the formation.The TDS content of the oil recovery formulation water may also beadjusted to optimize the viscosity of the oil recovery formulation,since the viscosity of the oil recovery formulation is dependent in parton the viscosity of the polymer in the formulation, which may bedependent on the salinity of the formulation. Determination of theoptimum salinity of the oil recovery formulation water for minimizinginterfacial tension of the oil and water in the oil-bearing formationand for providing a viscosity on the same order of magnitude as the oilin the formation may be conducted according to methods conventional andknown to those skilled in the art. One such method is described in WOPub. No. 2011/090921. Salinity optimization of the water may beconducted in accordance with methods conventional and known to thoseskilled in the art, for example, salt concentrations may be decreased byionic filtration using one or more nanofiltration membrane units, one ormore reverse osmosis membrane units, and/or one or more forward osmosismembrane units; salt concentrations may be increased by adding one ormore salts, preferably NaCl, to the water; salt concentrations may bedecreased by ion exchange with an ionic exchange material that releaseshydrogen and hydroxide ions in exchange for ions in the water, and saltconcentrations may be increased or decreased by blending of theresulting permeates and retentates of ionic filtration to provideoptimum salinity.

The oil recovery formulation may also be comprised of a co-solventmiscible with water, where the co-solvent may be a low molecular weightalcohol including, but not limited to, methanol, ethanol, and propanol,isobutyl alcohol, secondary butyl alcohol, n-butyl alcohol, t-butylalcohol, or a glycol including, but not limited to, ethylene glycol,1,3-propanediol, 1,2-propandiol, diethylene glycol butyl ether,triethylene glycol butyl ether, or a sulfosuccinate including, but notlimited to, sodium dihexyl sulfosuccinate. The co-solvent may beutilized for the purpose of adjusting the salinity of the oil recoveryformulation fluid to optimize the salinity of the fluid for maximumreduction of interfacial tension between oil and water in the formation,and, optionally, for assisting in prevention of formation of a viscousemulsion upon conducting the EOR process. If present, the co-solvent maycomprise from 100 ppm to 50000 ppm, or from 500 ppm to 5000 ppm of theoil recovery formulation. A co-solvent may be absent from the oilrecovery formulation, and the oil recovery formulation may be free of aco-solvent.

The oil recovery formulation further comprises ammonia, where theammonia may interact with oil in the formation to form a soap effectiveto reduce the interfacial tension between oil and water in theformation. The ammonia may also reduce surfactant adsorption on thereservoir rock surfaces. An ammonia liquid may be mixed with othercomponents of the enhanced oil recovery formulation to form the enhancedoil recovery formulation, where the ammonia liquid may be mixed with theother enhanced oil recovery formulation components 1) prior tointroduction of the enhanced oil recovery formulation to the oil-bearingformation, or 2) after one or more of the enhanced oil recoveryformulation components have been individually introduced into theformation, or 3) simultaneously with introduction of one or more of theenhanced oil recovery formulation components into the formation, butseparate from at least one of the components. The ammonia liquid mixedwith the other components of the oil recovery formulation to form theoil recovery formulation utilized in the ASP EOR process and system ofthe present invention, and to form the composition of the presentinvention, may be an ammonia liquid comprising at most 10 wt. % water,or at most 5 wt. % water, or at most 1 wt. % water and at least 90 wt. %ammonia. Most preferably, the ammonia liquid is anhydrous liquid ammoniato minimize the weight and space requirements for storing and utilizingthe liquid ammonia in the ASP EOR process and system of the presentinvention.

The oil recovery formulation further comprises an alkali metal carbonateor an alkali metal bicarbonate, where the alkali metal carbonate orbicarbonate may be effective to form precipitates with calcium cationsencountered by the oil recovery formulation in the oil-bearingformation. The alkali metal carbonate or bicarbonate may also interactwith oil in the formation to form a soap effective to reduce theinterfacial tension between oil and water in the formation. The alkalimetal carbonate or bicarbonate is preferably selected from the groupconsisting of sodium carbonate, sodium bicarbonate, potassium carbonate,potassium bicarbonate, and mixtures thereof, and most preferably issodium carbonate. The alkali metal carbonate or bicarbonate, or anaqueous solution of an alkali metal carbonate or bicarbonate, may bemixed with other components of the enhanced oil recovery formulation toform the enhanced oil recovery formulation, where the alkali metalcarbonate or bicarbonate or aqueous solution of alkali metal carbonateor bicarbonate may be mixed with the other enhanced oil recoveryformulation components 1) prior to introduction of the enhanced oilrecovery formulation to the oil-bearing formation, or 2) after one ormore of the enhanced oil recovery formulation components have beenindividually introduced into the formation, or 3) simultaneously withintroduction of one or more of the enhanced oil recovery formulationcomponents into the formation, but separate from at least one of thecomponents.

The ammonia liquid and the alkali metal carbonate or bicarbonate aremixed with the other components of the oil recovery formulation, or arepresent in the oil recovery formulation, in an amount to provide the oilrecovery formulation with a pH of at least 10. The ammonia liquid mixedwith the other components of the oil recovery formulation, or theammonia present in the oil recovery formulation, may provide relativelyhighly buffered alkalinity to the oil recovery formulation due toammonia's dissociation constant, enabling the oil recovery formulationto have a relatively low but useful pH for an alkaline solution used inan ASP EOR process. The alkali metal carbonate or bicarbonate may alsoprovide relatively highly buffered alkalinity to the oil recoveryformulation. A relatively low alkaline pH ASP oil recovery formulation(e.g. pH 9 to pH 12) may be desirable for use in certain oil-bearingformations to prevent dissolution of formation minerals by strongalkalinity (e.g. pH>12)—for example, sandstone formations containingsignificant quantities of silica quartz. Furthermore, the relativelyhighly buffered alkalinity provided to the oil recovery formulation bythe ammonia and the alkali metal carbonate or bicarbonate may decreasethe time required and the amount of oil recovery formulation requiredfor the oil recovery formulation to breakthrough from an injection wellto a production well in the ASP EOR process of the present invention:alkalis that are not highly buffered react with the formation,increasing the amount oil recovery formulation and time required for theoil recovery formulation to breakthrough from an injection well to aproduction well.

Preferably the ammonia liquid and the alkali metal carbonate orbicarbonate are mixed with the other components of the oil recoveryformulation, or are present in the oil recovery formulation, in anamount sufficient to provide the oil recovery formulation with aninitial pH of from 10 to 12. The ammonia liquid may be mixed with theother components of the oil recovery formulation, or may be present inthe oil recovery formulation, in an amount to provide ammonia in aconcentration in the oil recovery formulation of from 0.01 M to 2 M, orfrom 0.1 M to 1 M, or in an amount that is from 0.01 wt. % to 5 wt. %,or from 0.1 wt. % to 2 wt. %, of the total combined weight of thesurfactant, polymer, alkali metal carbonate or bicarbonate, ammonialiquid, and water of the oil recovery formulation.

The alkali metal carbonate or bicarbonate may be mixed with the othercomponents of the oil recovery formulation, or may be present in the oilrecovery formulation, in an amount sufficient to provide the oilrecovery formulation with an initial pH of from 10-12 in combinationwith the ammonia liquid. The alkali metal carbonate or bicarbonate maybe present in the oil recovery formulation in at least an amountsufficient to precipitate a significant amount of calcium cationsinstantaneously contacted by the oil recovery formulation in theformation, preferably at least 50%, or at least 75%, or at least 90%, orat least 95%, or at least 99%, or substantially all, or 100% of thecalcium cations instantaneously contacted by the oil recoveryformulation in the formation. Preferably, the amount of alkali metalcarbonate or bicarbonate mixed with other components of the oil recoveryformulation, or present in the oil recovery formulation, is limited toan amount of at most 10 times, or at most 5 times, or at most 1 timesthat required to precipitate 100% of calcium cations in the formationthat may be instantaneously contacted with the oil recovery formulation.The amount of alkali metal carbonate or alkali metal bicarbonate mixedwith other components of the oil recovery formulation, or present in theoil recovery formulation, may be from 0.001 wt. % to 2 wt. %, or from0.01 wt. % to 1 wt. %, from 0.05 wt. % to 0.5 wt. % of the totalcombined weight of the surfactant, polymer, alkali metal carbonate orbicarbonate, ammonia liquid, and water of the oil recovery formulation.

The amount of alkali metal carbonate or alkali metal bicarbonatesufficient to precipitate 100% of the calcium cations in the formationinstantaneously contacted by the oil recovery formulation in theformation may be directly reasonably approximated if the formationcontains connate water or formation brine containing insignificantquantities of calcium (e.g. at most 200 ppm calcium) that wouldprecipitate as calcium salts upon contact with the alkali metalcarbonate or bicarbonate. In an embodiment of the process of the presentinvention, if the formation contains connate water or formation brinehaving a calcium content of greater than 200 ppm, the formation may betreated with a softened brine having a calcium content of at most 10 ppmprior to contact with the oil recovery formulation so that alkali of thealkali metal carbonate or bicarbonate is not substantially precipitatedas calcium salts formed by contact with calcium contained in solution inthe connate water or formation brine.

When the formation contains connate water or formation brine containinginsignificant quantities of calcium, calcium cations present in theformation that may be instantaneously contacted by the oil recoveryformation are primarily located on cation binding ion exchange siteswithin the formation. Since a negligible amount of multivalent cationshaving a valency of 3 or greater are present in a formation relative tomonovalent and divalent cations, a reasonable approximation of theconcentration of calcium cations on cation binding sites in a formationmay be determined. The concentration of all monovalent cations and alldivalent cations (in equivalents) present in the formation water may bemeasured, and the fraction of formation rock ion exchange sites that arebinding divalent cations and that are to be swept by the oil recoveryformulation may be calculated according to equations 1 and 2.

$\begin{matrix}{{(++)_{r} = \frac{\left( {k + 2} \right) - \sqrt{k^{2} + {4k}}}{2}}{where}} & \left( {{equation}\mspace{14mu} 1} \right) \\{k = {\left\lbrack \frac{\lbrack + \rbrack_{w}^{2}}{\lbrack++\rbrack_{w}} \right\rbrack*{P.V.}}} & \left( {{equation}\mspace{14mu} 2} \right)\end{matrix}$

-   -   where P. V. is the fractional pore volume of the oil recovery        formulation to be utilized to sweep the formation, where        subscript (w) indicates an ion in formation water and        subscript (r) indicates a formation rock site occupied by a ion,        and [+]_(w) indicates monovalent cation concentration (in        equivalents) in formation water, [++]_(w) indicates divalent        cation concentration (in equivalents) in formation water, and        (++)_(r) indicates the fraction of formation rock ion exchange        sites that are occupied by a divalent cation where

$(++)_{r} = {\frac{\left( {{equivalents}++} \right)_{r}}{\left\{ {\left( {{equivalents}++} \right)_{r} + \left( {{equivalents} +} \right)_{r}} \right\}}.}$

The fraction of formation rock ion exchange sites occupied by calciumcations ((Ca²⁺)_(r)) and that are to be swept by the oil recoveryformulation may be calculated by measuring the concentration of calciumions in the formation water, calculating the ratio of calcium ionconcentration in the formation water to total divalent cationconcentration in the formation water, and multiplying the calculatedfraction of formation rock ion exchange sites to be swept by the oilrecovery formulation that are binding divalent cations by the calculatedratio of calcium cations in the formation water to the total divalentcations in the formation water as shown in equation (3):

(Ca²⁺)_(r)=(++)_(r)*([Ca²⁺]_(w)/[++]_(w))  (equation 3).

The concentration of calcium cations per volume of the formation may bedetermined by measuring the grain density, the porosity, and the cationexchange capacity (CEC) of the formation, calculating the volume of porespace in the formation rock according to equation (4)

$\begin{matrix}{{V_{{pore}\mspace{14mu} {space}\mspace{14mu} {per}\mspace{14mu} 100\mspace{14mu} {grams}\mspace{14mu} {formation}\mspace{14mu} {rock}} = {\left( \frac{100\mspace{14mu} g}{{Grain}\mspace{14mu} {Density}} \right)*\left( \frac{Porosity}{\left( {1 - {Porosity}} \right)} \right)}},} & \left( {{equation}\mspace{14mu} 4} \right)\end{matrix}$

calculating the cation exchange capacity of the formation per volume ofthe formation according to equation (5)

$\begin{matrix}{{{CEC}_{{per}\mspace{14mu} {volume}\mspace{14mu} {of}\mspace{14mu} {{formation}{({{{meq}/{ml}}\mspace{14mu} {of}\mspace{14mu} {pore}\mspace{14mu} {space}})}}} = \frac{{CEC}_{formation}\left( \frac{meq}{100\mspace{14mu} g} \right)}{V_{{pore}\mspace{14mu} {space}\mspace{14mu} {per}\mspace{14mu} 100\mspace{14mu} {grams}\mspace{14mu} {formation}\mspace{14mu} {rock}}}},} & \left( {{equation}\mspace{14mu} 5} \right)\end{matrix}$

and calculating the concentration of calcium cations (inmilliequivalents) per volume of the formation according to equation (6):

$\begin{matrix}{\left\lbrack {Ca}^{2 +} \right\rbrack_{{per}\mspace{14mu} {volume}\mspace{14mu} {of}\mspace{14mu} {{formation}{({{meq}/{ml}})}}} = {{CEC}_{{per}\mspace{14mu} {volume}\mspace{14mu} {of}\mspace{14mu} {formation}}*{\left( {Ca}^{2 +} \right)_{r{({{{Ca}\; 2} + {{fraction}\mspace{14mu} {on}\mspace{14mu} {formation}\mspace{14mu} {rock}\mspace{14mu} {ion}\mspace{14mu} {exchange}\mspace{14mu} {sites}}})}}.}}} & \left( {{equation}\mspace{14mu} 6} \right)\end{matrix}$

The concentration of alkali carbonate in milliequivalents per milliliterof an oil recovery formulation containing 1 wt % of the alkali carbonatein solution may be calculated according to equation (7), assuming theoil recovery formulation has a density of about 1 (a good approximationfor dilute aqueous solutions):

$\begin{matrix}{{\left\lbrack {{Alk}.{Carbonate}} \right\rbrack_{{per}\mspace{14mu} {volume}\mspace{14mu} {oil}\mspace{14mu} {recovery}\mspace{14mu} {formation}}\left( {{meq}\text{/}{ml}} \right)} = {2*{\left\lbrack \frac{\left( {1\left( {{wt}\%} \right){{Alk}.{Carbonate}}\mspace{14mu} {formation}} \right)*10}{{Molecular}\mspace{14mu} {{Wt}.\mspace{14mu} {of}}\mspace{14mu} {Alkali}\mspace{14mu} {Carbonate}} \right\rbrack.}}} & \left( {{equation}\mspace{14mu} 7} \right)\end{matrix}$

The approximate amount of alkali carbonate (wt. %) in the oil recoveryformulation required to precipitate all of the calcium in the formationin a volume swept by the oil recovery formulation may then be calculatedbased on the fractional pore volume (P. V.) of oil recovery formulationused to sweep the formation, and the concentration of calcium ions pervolume of the formation (meq/ml) and the concentration of alkalicarbonate at 1% concentration (meq/ml) per volume of oil recoveryformulation according to equation (8):

$\begin{matrix}{{{Alkali}\mspace{14mu} {carbonate}\mspace{14mu} {required}\mspace{14mu} {in}\mspace{14mu} {oil}\mspace{14mu} {recovery}\mspace{14mu} {formation}\mspace{14mu} \left( {{wt}\%} \right)} = {\frac{\left\lbrack {{{Ca}\; 2} +} \right\rbrack {per}\mspace{14mu} {volume}\mspace{14mu} {of}\mspace{14mu} {formation}}{\left( \begin{matrix}{\left\lbrack {1\mspace{14mu} {wt}\mspace{14mu} \% \mspace{14mu} {{Alk}.{Carbonate}}} \right\rbrack {per}\mspace{14mu} {volume}\mspace{14mu} {oil}} \\{{recovery}\mspace{14mu} {formulation}\mspace{14mu}*\mspace{14mu} {P.V.\mspace{14mu} {of}}\mspace{14mu} {oil}\mspace{14mu} {recovery}\mspace{14mu} {formation}}\end{matrix} \right.}.}} & \left( {{equation}\mspace{14mu} 8} \right)\end{matrix}$

The oil recovery formulation further comprises a surfactant, where thesurfactant may be any surfactant effective to reduce the interfacialtension between oil and water in the oil-bearing formation and therebymobilize the oil for production from the formation. The surfactant maybe mixed with other components of the enhanced oil recovery formulationto form the enhanced oil recovery formulation, where the surfactant maybe mixed with the other enhanced oil recovery formulation components 1)prior to introduction of the enhanced oil recovery formulation to theoil-bearing formation, or 2) after one or more of the enhanced oilrecovery formulation components have been individually introduced intothe formation, or 3) simultaneously with introduction of one or more ofthe enhanced oil recovery formulation components into the formation, butseparate from at least one of the components. The oil recoveryformulation may comprise one or more surfactants. The surfactant may bean anionic surfactant. The anionic surfactant may be asulfonate-containing compound, a sulfate-containing compound, acarboxylate compound, a phosphate compound, or a blend thereof. Theanionic surfactant may be an alpha olefin sulfonate compound, aninternal olefin sulfonate compound, a branched alkyl benzene sulfonatecompound, a propylene oxide sulfate compound, an ethylene oxide sulfatecompound, a propylene oxide-ethylene oxide sulfate compound, or a blendthereof. The anionic surfactant may be a surfactant that forms a waterinsoluble calcium salt in the presence of calcium cations. The anionicsurfactant may be stable at temperatures of from 50° C. to 90° C., orfrom 60° C. to 75° C. The anionic surfactant may contain from 12 to 28carbons, or from 12 to 20 carbons. The surfactant of the oil recoveryformulation may comprise an internal olefin sulfonate compoundcontaining from 15 to 18 carbons or a propylene oxide sulfate compoundcontaining from 12 to 15 carbons, or a blend thereof, where the blendcontains a volume ratio of the propylene oxide sulfate to the internalolefin sulfonate compound of from 1:1 to 10:1.

The oil recovery formulation may contain an amount of the surfactanteffective to reduce the interfacial tension between oil and water in theformation and thereby mobilize the oil for production from theformation. The oil recovery formation may contain from 0.05 wt. % to 5wt. % of the surfactant or combination of surfactants, or may containfrom 0.1 wt. % to 3 wt. % of the surfactant or combination ofsurfactants.

The oil recovery formulation further comprises a polymer, where thepolymer may provide the oil recovery formulation with a viscosity on thesame order of magnitude as the viscosity of oil in the formation underformation temperature conditions so the oil recovery formulation maydrive mobilized oil across the formation for production from theformation with a minimum of fingering of the oil through the oilrecovery formulation and/or fingering of the oil recovery formulationthrough the oil. The polymer may be in an aqueous solution or an aqueousdispersion prior to being mixed to form the enhanced oil recoveryformulation. The polymer may be mixed with other components of theenhanced oil recovery formulation to form the enhanced oil recoveryformulation, where the polymer may be mixed with the other enhanced oilrecovery formulation components 1) prior to introduction of the enhancedoil recovery formulation to the oil-bearing formation, or 2) after oneor more of the enhanced oil recovery formulation components have beenindividually introduced into the formation, or 3) simultaneously withintroduction of one or more of the enhanced oil recovery formulationcomponents into the formation, but separate from at least one of thecomponents.

The oil recovery formulation may comprise a polymer selected from thegroup consisting of polyacrylamides, partially hydrolyzedpolyacrylamides, polyacrylates, ethylenic co-polymers, biopolymers,carboxymethylcelloluses, polyvinyl alcohols, polystyrene sulfonates,polyvinylpyrrolidones, AMPS (2-acrylamide-methyl propane sulfonate), andcombinations thereof. Examples of ethylenic co-polymers includeco-polymers of acrylic acid and acrylamide, acrylic acid and laurylacrylate, and lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum and guar gum.

The quantity of polymer in the oil recovery formulation should besufficient to provide the oil recovery formulation with a viscositysufficient to drive the oil through the oil-bearing formation with aminimum of mobilized oil fingering through the oil recovery formulationand, optionally, a minimum of fingering of the oil recovery formulationthrough the mobilized oil. The quantity of the polymer in the oilrecovery formulation may be sufficient to provide the oil recoveryformulation with a dynamic viscosity at formation temperatures on thesame order of magnitude, or, less preferably a greater order ofmagnitude, as the dynamic viscosity of the oil in the oil-bearingformation at formation temperatures so the oil recovery formulation maypush the oil through the formation. In a preferred embodiment, the oilrecovery formulation may have a dynamic viscosity within 400%, or within300%, or within 200% of the dynamic viscosity of the oil in theoil-bearing formation when measured isothermally. The quantity of thepolymer in the oil recovery formulation may be sufficient to provide theoil recovery formulation with a dynamic viscosity of at least 1 mPa s (1cP), or at least 10 mPa s (10 cP), or at least 50 mPa (50 cP), or atleast 100 mPa s (100 cP) at 25° C. or at a temperature within aformation temperature range. The concentration of polymer in the oilrecovery formulation may be from 200 ppm to 10000 ppm, or from 500 ppmto 5000 ppm, or from 1000 to 2500 ppm.

The molecular weight average of the polymer in the oil recoveryformulation should be sufficient to provide sufficient viscosity to theoil recovery formulation to drive the mobilized oil through theformation. The polymer may have a molecular weight average of from10,000 to 30,000,000 daltons, or from 100,000 to 10,000,000 daltons.

In one aspect, the present invention is directed to an oil recoveryformulation composition comprising water, ammonia, an alkali metalcarbonate and/or bicarbonate, a surfactant, and a polymer. The water,ammonia, alkali metal carbonate and/or bicarbonate, surfactant, andpolymer may be as described above. The oil recovery formulationcomposition may contain an amount of ammonia liquid comprising at most10 wt. % water, preferably anhydrous liquid ammonia, in an amounteffective to provide the oil recovery formulation with an initial pH offrom 10 to 12, or an ammonia concentration of from 0.01 M to 2 M, orfrom 0.01 wt. % to 5 wt. % ammonia; from 0.001 wt. % to 2 wt. %. or from0.01 wt. % to 1 wt. %, or from 0.05 wt. % to 0.5 wt. % of an alkalimetal carbonate and/or bicarbonate; from 0.05 wt. % to 5 wt. %, or from0.1 wt. % to 3 wt. % of the surfactant or combination of surfactants;and from 200 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000to 2500 ppm of the polymer or a combination of polymers.

In the method of the present invention, the oil recovery formulation is,or components of the oil recovery formulation are, introduced into anoil-bearing formation, and the system of the present invention includesan oil-bearing formation. The oil-bearing formation comprises oil thatmay be separated and produced from the formation after contact andmixing with the oil recovery formulation. The oil of the oil-bearingformation may contain oil having a total acid number (TAN) expressed inmilligrams of KOH per gram of sample of at least 0.1 or at least 0.3 orat least 0.5, wherein the TAN of an oil may be determined in accordancewith ASTM Method D664. Oils having a TAN of at least 0.1 containsignificant quantities of acidic moieties that may interact with ammoniaand/or an alkali metal carbonate or bicarbonate to form a soap whentreated with an oil recovery formulation comprising ammonia and analkali metal carbonate and/or bicarbonate, thereby reducing interfacialtension between oil and water in the formation and mobilizing the oilfor production from the formation.

The oil contained in the oil-bearing formation may be a light oil or anintermediate weight oil containing less than 25 wt. %, or less than 20wt. %, or less than 15 wt. %, or less than 10 wt. %, or less than 5 wt.% of hydrocarbons having a boiling point of at least 538° C. (1000° F.)and having an API gravity as determined in accordance with ASTM MethodD6882 of at least 20°, or at least 25°, or at least 30°. Alternatively,but less preferably, the oil of the oil bearing-formation may be a heavyoil containing more than 25 wt. % of hydrocarbons having a boiling pointof at least 538° C. and having an API gravity of less than 20°.

The oil contained in the oil-bearing formation may have a dynamicviscosity under formation conditions (in particular, at temperatureswithin the temperature range of the formation) of at least 0.4 mPa s(0.4 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP),or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP).The oil contained in the oil-bearing formation may have a dynamicviscosity under formation temperature conditions of from 0.4 to 10000000mPa s (0.4 to 10000000 cP).

The oil-bearing formation may be a subterranean formation. Thesubterranean formation may be comprised of one or more porous matrixmaterials selected from the group consisting of a porous mineral matrix,a porous rock matrix, and a combination of a porous mineral matrix and aporous rock matrix, where the porous matrix material may be locatedbeneath an overburden at a depth ranging from 50 meters to 6000 meters,or from 100 meters to 4000 meters, or from 200 meters to 2000 metersunder the earth's surface.

The subterranean formation may be a subsea subterranean formation. Themethod and system of the present invention may be particularly suitedfor recovering oil from an oil-bearing subsea subterranean formationutilizing an offshore oil recovery platform.

The porous matrix material may be a consolidated matrix material inwhich at least a majority, and preferably substantially all, of the rockand/or mineral that forms the matrix material is consolidated such thatthe rock and/or mineral forms a mass in which substantially all of therock and/or mineral is immobile when oil, the oil recovery formulation,water, or other fluid is passed therethrough. Preferably at least 95 wt.% or at least 97 wt. %, or at least 99 wt. % of the rock and/or mineralis immobile when oil, the oil recovery formulation, water, or otherfluid is passed therethrough so that any amount of rock or mineralmaterial dislodged by the passage of the oil, oil recovery formulation,water, or other fluid is insufficient to render the formationimpermeable to the flow of the oil recovery formulation, oil, water, orother fluid through the formation. The porous matrix material may be anunconsolidated matrix material in which at least a majority, orsubstantially all, of the rock and/or mineral that forms the matrixmaterial is unconsolidated. The formation may have a permeability offrom 0.0001 to 15 Darcys, or from 0.001 to 1 Darcy. The rock and/ormineral porous matrix material of the formation may be comprised ofsandstone and/or a carbonate selected from dolomite, limestone, andmixtures thereof—where the limestone may be microcrystalline orcrystalline limestone and/or chalk. The rock and/or mineral porousmatrix material of the formation may include significant quantities ofsilica quartz since the alkalinity of the ammonia based oil recoveryformulation may be sufficiently low to avoid dissolution of thesilica-quartz.

Oil in the oil-bearing formation may be located in pores within theporous matrix material of the formation. The oil in the oil-bearingformation may be immobilized in the pores within the porous matrixmaterial of the formation, for example, by capillary forces, byinteraction of the oil with the pore surfaces, by the viscosity of theoil, or by interfacial tension between the oil and water in theformation.

The oil-bearing formation may also be comprised of water, which may belocated in pores within the porous matrix material. The water in theformation may be connate water, water from a secondary or tertiary oilrecovery process water-flood, or a mixture thereof. The water in theoil-bearing formation may be positioned in the formation to immobilizeoil within the pores. Contact of the oil recovery formulation with theoil and water in the formation may mobilize the oil in the formation forproduction and recovery from the formation by freeing at least a portionof the oil from pores within the formation by reducing interfacialtension between water and oil in the formation.

In some embodiments, the oil-bearing formation may compriseunconsolidated sand and water. The oil-bearing formation may be an oilsand formation. In some embodiments, the oil may comprise between about1 wt. % and about 16 wt. % of the oil/sand/water mixture, the sand maycomprise between about 80 wt. % and about 85 wt. % of the oil/sand/watermixture, and the water may comprise between about 1 wt. % and about 16wt. % of the oil/sand water mixture. The sand may be coated with a layerof water with the petroleum being located in the void space around thewetted sand grains. Optionally, the oil-bearing formation may alsoinclude a gas, such as methane or air, for example.

The oil-bearing formation may be comprised of calcium cations and/orcalcium compounds or salts from which calcium cations may be displaced.The calcium cations and/or calcium compounds or salts from which calciumcations may be displaced may be present in the connate water within theformation. The calcium cations may be present in the connate water in aconcentration of from 10 ppm to 30,000 ppm. The calcium cations and/orcalcium compounds or salts from which calcium cations may be displacedmay be present in porous matrix material of the formation, as describedabove.

Referring now to FIG. 1, a system 200 of the present invention forpracticing a method of the present invention is shown. The systemincludes a first well 201 and a second well 203 extending into anoil-bearing formation 205 such as described above. The oil-bearingformation 205 may be comprised of one or more formation portions 207,209, and 211 formed of porous material matricies, such as describedabove, located beneath an overburden 213. The oil-bearing formation 205may be a subsea formation where the first well 201 and the second well203 may extend from one or more offshore platforms 215 located on thesurface of the sea 217 above the oil-bearing formation 205.

In an embodiment, the system includes an oil recovery formulationcomprising water as described above, ammonia as described above, analkali metal carbonate or bicarbonate as described above, a surfactantas described above, and a polymer as described above. The salinity ofthe oil recovery formulation may be selected and/or adjusted to optimizethe interfacial tension reducing capacity of the surfactant and/or theammonia and/or the alkali metal carbonate or bicarbonate of the oilrecovery formulation with oil in the oil-bearing formation, and/or tooptimize the viscosity of the oil recovery formulation, as describedabove. The oil recovery formulation may be provided from an oil recoveryformulation storage facility 219 fluidly operatively coupled to a firstinjection/production facility 221 via conduit 223. Firstinjection/production facility 221 may be fluidly operatively coupled tothe first well 201, which may be located extending from the firstinjection/production facility 221 into the oil-bearing formation 205.The oil recovery formulation may flow from the firstinjection/production facility 221 through the first well 201 to beintroduced into the formation 205, for example in formation portion 209,where the first injection/production facility 221 and the first well, orthe first well itself, include(s) a mechanism for introducing the oilrecovery formulation into the formation. Alternatively, the oil recoveryformulation may flow from the oil recovery formulation storage facility219 directly to the first well 201 for injection into the formation 205,where the first well may comprise a mechanism for introducing the oilrecovery formulation into the formation. The mechanism for introducingthe oil recovery formulation into the formation 205 via the first well201—located in the first injection/production facility 221, the firstwell 201, or both—may be comprised of a pump 225 for delivering the oilrecovery formulation to perforations or openings in the first wellthrough which the oil recovery formulation may be introduced into theformation.

In another embodiment as shown in FIG. 2, the system may includeseparate storage facilities for one or more of the ammonia liquid,alkali metal carbonate or bicarbonate, surfactant, and polymer of theenhanced oil recovery formulation. The ammonia liquid may be stored inan ammonia liquid storage facility 227, and may contain up to 10 wt. %water, or up to 5 wt. % water, or may be anhydrous liquid ammonia. Thealkali metal carbonate or bicarbonate, either as an aqueous solution oras a solid material, may be stored in an alkali metal carbonate orbicarbonate storage facility 228. The surfactant may be stored in asurfactant storage facility 229, and may be an anionic surfactant asdescribed above. The polymer may be stored in a polymer storage facility231, and may be a polymer as described above.

Water may be provided from source water—for example sea water, producedformation water, lake water, aquifer water, or river water—treated in awater treatment facility 233 to adjust the salinity of the water to anoptimum salinity for use in the oil recovery formulation as describedabove. The water treatment facility may be operatively fluidly coupledto the alkai carbonate or bicarbonate storage facility 228 via conduit234 to provide water for mixing with the alkali metal carbonate orbicarbonate, if necessary; and/or may be operatively fluidly coupled tothe surfactant storage facility 229 via conduit 235 to provide water formixing with the surfactant to form a solution of the surfactant; and/ormay be operatively fluidly coupled to the polymer storage facility 231via conduit 237 to provide water for mixing with the polymer to form asolution of the polymer. Alternatively, the alkali metal carbonate orbicarbonate stored in the alkali metal carbonate or bicarbonate storagefacility 228 may be a pre-mixed aqueous alkali metal carbonate orbicarbonate solution, and/or the surfactant stored in the surfactantstorage facility 229 may be a pre-mixed aqueous surfactant solution,and/or the polymer stored in the polymer storage facility 231 may be apre-mixed aqueous polymer solution.

The ammonia liquid, alkali metal carbonate or bicarbonate, surfactant,and polymer may be provided from the ammonia liquid storage facility227, the alkali metal carbonate or bicarbonate storage facility 228, thesurfactant storage facility 229, and the polymer storage facility 231,respectively, to the oil recovery formulation storage facility 219wherein the ammonia liquid, the alkali metal carbonate or bicarbonate,the surfactant, and the polymer may be mixed and stored as the oilrecovery formulation. The ammonia liquid storage facility 227 may beoperatively fluidly coupled to the oil recovery formulation storagefacility 219 by conduit 239; the alkali metal carbonate or bicarbonatestorage facility 228 may be fluidly operatively coupled to the oilrecovery formulation storage facility by conduit 240; the surfactantstorage facility 229 may be operatively fluidly coupled to the oilrecovery formulation storage facility by conduit 241; and the polymerstorage facility 231 may be operatively fluidly coupled to the oilrecovery formulation storage facility by conduit 243. Water for the oilrecovery formulation, if necessary, may be provided from source watertreated in the water treatment facility 233, wherein the water treatmentfacility may be operatively fluidly coupled to the oil recoveryformulation storage facility 219 by conduit 245.

The oil recovery formulation may be provided from the oil recoveryformulation storage facility 219 to the first injection/productionfacility 221 or to the first well 201 for injection into the formation205 as described above.

Alternatively, the ammonia liquid, the alkali metal carbonate orbicarbonate, the surfactant, and the polymer may be provided separatelyfrom the ammonia liquid storage facility 227, the alkali metal carbonateor bicarbonate storage facility 228, the surfactant storage facility229, and the polymer storage facility 231, respectively, to the firstinjection/production facility 221 or to the first well 201 for injectioninto the formation 205. The ammonia liquid storage facility 227 may befluidly operatively coupled to the first injection/production facility221 or the first well 201 by conduit 247; the alkali metal carbonate orbicarbonate storage facility 228 may be fluidly operatively coupled orcoupled for powdered solid flow to the first injection/productionfacility or the first well by conduit 248, the surfactant storagefacility 229 may be fluidly operatively coupled to the firstinjection/production facility or the first well by conduit 249; and thepolymer storage facility 231 may be fluidly operatively coupled to thefirst injection/production facility or the first well by conduit 251.Ammonia liquid, one or more alkali metal carbonate or bicarbonatecompounds, one or more surfactants, and/or one or more polymers, andoptionally water, may be provided separately to the firstinjection/production facility 221 or the first well 201 and may be mixedin the first injection/production facility or the first well to form theoil recovery formulation for injection into the formation. Alternativelythe ammonia liquid, one or more alkali metal carbonate or bicarbonatecompounds, one or more surfactants, one or more polymers, and optionallyadditional water, may be injected into the formation 205 via the firstwell 201 separately or in a combination that does not form the completeoil recovery formulation, and the ammonia liquid, one or more alkalimetal carbonate or bicarbonate compounds, one or more surfactants, oneor more polymers, and optionally water, may be mixed to form the oilrecovery formulation within the formation, where the oil recoveryformulation formed within the formation may then be contacted with oilin the formation to mobilize the oil for production from the formation.

Referring now to both FIGS. 1 and 2, the oil recovery formulation may beintroduced into the formation 205, for example by injecting the oilrecovery formulation into the formation through the first well 201 bypumping the oil recovery formulation through the first well and into theformation, or by pumping the components of the oil recovery formulationthrough the first well into the formation for mixing within theformation to form the oil recovery formulation in situ. The pressure atwhich the oil recovery formulation or the components of the oil recoveryformulation is/are introduced into the formation may range from theinstantaneous pressure in the formation up to, but not including, thefracture pressure of the formation. The pressure at which the oilrecovery formulation or its components may be injected into theformation may range from 20% to 95%, or from 40% to 90%, of the fracturepressure of the formation. Alternatively, the oil recovery formulationor its components may be injected into the formation at a pressure equalto, or greater than, the fracture pressure of the formation.

The volume of oil recovery formulation or combined components of the oilrecovery formulation introduced into the formation 205 via the firstwell 201 may range from 0.001 to 5 pore volumes, or from 0.01 to 2 porevolumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes,where the term “pore volume” refers to the volume of the formation thatmay be swept by the oil recovery formulation or combined components ofthe oil recovery formulation between the first well 201 and the secondwell 203. The pore volume may be readily be determined by methods knownto a person skilled in the art, for example by modeling studies or byinjecting water having a tracer contained therein through the formation205 from the first well 201 to the second well 203.

As the oil recovery formulation is introduced into the formation 205 oras the components of the oil recovery formulation are individuallyintroduced into the formation and mixed therein to form the oil recoveryformulation, the oil recovery formulation spreads into the formation asshown by arrows 253. Upon introduction to the formation 205 or uponmixing of components of the oil recovery formulation in the formation toform the oil recovery formulation, the oil recovery formulation contactsand forms a mixture with a portion of the oil in the formation. The oilrecovery formulation may mobilize the oil in the formation uponcontacting and mixing with the oil and water in the formation. The oilrecovery formulation may mobilize the oil in the formation uponcontacting and mixing with the oil, for example, by reducing capillaryforces retaining the oil in pores in the formation, by reducing thewettability of the oil on pore surfaces in the formation, by reducingthe interfacial tension between oil and water in the formation, and/orby forming a microemulsion with oil and water in the formation.

The mobilized mixture of the oil recovery formulation and oil and watermay be pushed across the formation 205 from the first well 201 to thesecond well 203 by further introduction of more oil recovery formulationor components of the oil recovery formulation into the formation. Theoil recovery formulation may be designed to displace the mobilizedmixture of the oil recovery formulation and oil through the formation205 for production at the second well 203. As described above, the oilrecovery formulation contains a polymer, wherein the oil recoveryformulation comprising the polymer may be designed to have a viscosityon the same order of magnitude as the viscosity of the oil in theformation under formation temperature conditions, so the oil recoveryformulation may drive the mobilized mixture of oil recovery formulation,oil, and water across the formation while inhibiting fingering of themixture of mobilized oil and oil recovery formulation through thedriving plug of oil recovery formulation and inhibiting fingering of thedriving plug of oil recovery formulation through the mixture ofmobilized oil and oil recovery formulation.

Oil may be mobilized for production from the formation 205 via thesecond well 203 by introduction of the oil recovery formulation and/orits components into the formation, where the mobilized oil is driventhrough the formation for production from the second well as indicatedby arrows 255 by introduction of the oil recovery formulation orcomponents of the oil recovery formulation into the formation via thefirst well 201. The oil mobilized for production from the formation 205may include the mobilized oil/oil recovery formulation mixture. Waterand/or gas may also be mobilized for production from the formation 205via the second well 203 by introduction of the oil recovery formulationor its components into the formation via the first well 201.

After introduction of the oil recovery formulation into the formation205 via the first well 201, oil may be recovered and produced from theformation via the second well 203. The system of the present inventionmay include a mechanism located at the second well for recovering andproducing the oil from the formation 205 subsequent to introduction ofthe oil recovery formulation or the components of the oil recoveryformulation into the formation, and may include a mechanism located atthe second well for recovering and producing the oil recoveryformulation, water, and/or gas from the formation subsequent tointroduction of the oil recovery formulation into the formation. Themechanism located at the second well 203 for recovering and producingthe oil, and optionally for recovering and producing the oil recoveryformulation, water, and/or gas may be comprised of a pump 257, which maybe located in a second injection/production facility 259 and/or withinthe second well 203. The pump 257 may draw the oil, and optionally theoil recovery formulation, water, and/or gas from the formation 205through perforations in the second well 203 to deliver the oil, andoptionally the oil recovery formulation, water, and/or gas, to thesecond injection/production facility 259.

Alternatively, the mechanism for recovering and producing the oil—andoptionally the oil recovery formulation, water, and/or gas—from theformation 205 may be comprised of a compressor 261 that may be locatedin the second injection/production facility 259. The compressor 261 maybe fluidly operatively coupled to a gas storage tank 263 via conduit265, and may compress gas from the gas storage tank for injection intothe formation 205 through the second well 203. The compressor maycompress the gas to a pressure sufficient to drive production of oil—andoptionally the oil recovery formulation, water, and/or gas—from theformation via the second well 203, where the appropriate pressure may bedetermined by conventional methods known to those skilled in the art.The compressed gas may be injected into the formation from a differentposition on the second well 203 than the well position at which theoil—and optionally the oil recovery formulation, water, and/or gas—areproduced from the formation, for example, the compressed gas may beinjected into the formation at formation portion 207 while oil, oilrecovery formulation, water, and/or gas are produced from the formationat formation portion 209.

Oil, optionally in a mixture with the oil recovery formulation, water,and/or gas may be drawn from the formation 205 as shown by arrows 255and produced up the second well 203 to the second injection/productionfacility 259. The oil may be separated from the oil recoveryformulation, water, and/or gas in a separation unit 267 located in thesecond injection/production facility 259 and operatively fluidly coupledto the mechanism 257 for producing oil and, optionally, the oil recoveryformulation, water, and/or gas, from the formation. The separation unit267 may be comprised of a conventional liquid-gas separator forseparating gas from the oil, oil recovery formulation, and water; and aconventional hydrocarbon-water separator including a demulsificationunit for separating the oil from water and water soluble components ofthe oil recovery formulation.

The separated produced oil may be provided from the separation unit 267of the second injection/production facility 259 to an oil storage tank269, which may be fluidly operatively coupled to the separation unit 267of the second injection/production facility by conduit 271. Theseparated gas, if any, may be provided from the separation unit 267 ofthe second injection/production facility 259 to the gas storage tank263, which may be fluidly operatively coupled to the separation unit 267of the second injection/production facility 259 by conduit 273.

In an embodiment of a system and a method of the present invention, thefirst well 201 may be used for injecting the oil recovery formulationand/or its components into the formation 205 and the second well 203 maybe used to produce oil from the formation as described above for a firsttime period, and the second well 203 may be used for injecting the oilrecovery formulation and/or its components into the formation 205 tomobilize the oil in the formation and drive the mobilized oil across theformation to the first well and the first well 201 may be used toproduce oil from the formation for a second time period, where thesecond time period is subsequent to the first time period. The secondinjection/production facility 259 may comprise a mechanism such as pump275 that may be fluidly operatively coupled the oil recovery formulationstorage facility 219 by conduit 277, and that is fluidly operativelycoupled to the second well 203 to introduce the oil recovery formulationinto the formation 205 via the second well. Alternatively, as shown inFIG. 2, the mechanism 275 may be fluidly operatively coupled to: theammonia liquid storage facility 227 via conduit 279; the alkali metalcarbonate or bicarbonate storage facility 228 via conduit 280; thesurfactant storage facility 229 via conduit 281; and the polymer storagefacility 231 by conduit 283 for introduction of the components of theoil recovery formulation into the formation via the second well 203.Referring again to FIGS. 1 and 2, the first injection/productionfacility 221 may comprise a mechanism such as pump 285, or compressor287 fluidly operatively coupled to the gas storage tank 263 by conduit289, for production of oil, and optionally the oil recovery formulation,water, and/or gas from the formation 205 via the first well 201. Thefirst injection/production facility 221 may also include a separationunit 291 for separating produced oil, oil recovery formulation, water,and/or gas. The separation unit 291 may be comprised of a conventionalliquid-gas separator for separating gas from the produced oil and water;and a conventional hydrocarbon-water separator for separating theproduced oil from water and water soluble components of the oil recoveryformulation, where the hydrocarbon-water separator may comprise ademulsifier. The separation unit 291 may be fluidly operatively coupledto: the oil storage tank 269 by conduit 293 for storage of produced oilin the oil storage tank; and the gas storage tank 263 by conduit 295 forstorage of produced gas in the gas storage tank.

The first well 201 may be used for introducing the oil recoveryformulation or the components of the oil recovery formulation into theformation 205 and the second well 203 may be used for producing oil fromthe formation for a first time period; then the second well 203 may beused for introducing the oil recovery formulation or components of theoil recovery formulation into the formation 205 and the first well 201may be used for producing oil from the formation for a second timeperiod; where the first and second time periods comprise a cycle.Multiple cycles may be conducted which include alternating the firstwell 201 and the second well 203 between introducing the oil recoveryformulation or its components into the formation 205 and producing oilfrom the formation, where one well is introducing and the other isproducing for the first time period, and then they are switched for asecond time period. A cycle may be from about 12 hours to about 1 year,or from about 3 days to about 6 months, or from about 5 days to about 3months.

Referring now to FIG. 3, an array of wells 300 is illustrated. Array 300includes a first well group 302 (denoted by horizontal lines) and asecond well group 304 (denoted by diagonal lines). In some embodimentsof the system and method of the present invention, the first well of thesystem and method described above may include multiple first wellsdepicted as the first well group 302 in the array 300, and the secondwell of the system and method described above may include multiplesecond wells depicted as the second well group 304 in the array 300.

Each well in the first well group 302 may be a horizontal distance 330from an adjacent well in the first well group 302. The horizontaldistance 330 may be from about 5 to about 5000 meters, or from about 10to about 1000 meters, or from about 20 to about 500 meters, or fromabout 30 to about 250 meters, or from about 50 to about 200 meters, orfrom about 90 to about 150 meters, or about 100 meters. Each well in thefirst well group 302 may be a vertical distance 332 from an adjacentwell in the first well group 302. The vertical distance 332 may be fromabout 5 to about 5000 meters, or from about 10 to about 1000 meters, orfrom about 20 to about 500 meters, or from about 30 to about 250 meters,or from about 50 to about 200 meters, or from about 90 to about 150meters, or about 100 meters.

Each well in the second well group 304 may be a horizontal distance 336from an adjacent well in the second well group 304. The horizontaldistance 336 may be from 5 to 5000 meters, or from 10 to 1000 meters, orfrom 20 to 500 meters, or from 30 to 250 meters, or from 50 to 200meters, or from 90 to 150 meters, or about 100 meters. Each well in thesecond well group 304 may be a vertical distance 338 from an adjacentwell in the second well group 304. The vertical distance 338 may be from5 to 5000 meters, or from 10 to about 1000 meters, or from 20 to 500meters, or from 30 to 250 meters, or from 50 to 200 meters, or from 90to 150 meters, or about 100 meters.

Each well in the first well group 302 may be a distance 334 from theadjacent wells in the second well group 304. Each well in the secondwell group 304 may be a distance 334 from the adjacent wells in firstwell group 302. The distance 334 may be from 5 to 5000 meters, or from10 to 1000 meters, or from 20 to 500 meters, or from 30 to 250 meters,or from 50 to 200 meters, or from 90 to 150 meters, or about 100 meters.

Each well in the first well group 302 may be surrounded by four wells inthe second well group 304. Each well in the second well group 304 may besurrounded by four wells in the first well group 302.

In some embodiments, the array of wells 300 may have from 10 to 1000wells, for example from 5 to 500 wells in the first well group 302, andfrom 5 to 500 wells in the second well group 304.

In some embodiments, the array of wells 300 may be seen as a top viewwith first well group 302 and the second well group 304 being verticalwells spaced on a piece of land. In some embodiments, the array of wells300 may be seen as a cross-sectional side view of the formation with thefirst well group 302 and the second well group 304 being horizontalwells spaced within the formation.

Referring now to FIG. 4, an array of wells 400 is illustrated. Array 400includes a first well group 402 (denoted by horizontal lines) and asecond well group 404 (denoted by diagonal lines). The array 400 may bean array of wells as described above with respect to array 300 in FIG.3. In some embodiments of the system and method of the presentinvention, the first well of the system and method described above mayinclude multiple first wells depicted as the first well group 402 in thearray 400, and the second well of the system and method described abovemay include multiple second wells depicted as the second well group 404in the array 400.

The oil recovery formulation or components thereof may be injected intofirst well group 402 and oil may be recovered and produced from thesecond well group 404. As illustrated, the oil recovery formulation mayhave an injection profile 406, and oil may be produced from the secondwell group 404 having a oil recovery profile 408.

The oil recovery formulation or components thereof may be injected intothe second well group 404 and oil may be produced from the first wellgroup 402. As illustrated, the oil recovery formulation may have aninjection profile 408, and oil may be produced from the first well group402 having an oil recovery profile 406.

The first well group 402 may be used for injecting the oil recoveryformulation or components thereof and the second well group 404 may beused for producing oil from the formation for a first time period; thensecond well group 404 may be used for injecting the oil recoveryformulation or components thereof and the first well group 402 may beused for producing oil from the formation for a second time period,where the first and second time periods comprise a cycle. In someembodiments, multiple cycles may be conducted which include alternatingfirst and second well groups 402 and 404 between injecting the oilrecovery formulation or components thereof and producing oil from theformation, where one well group is injecting and the other is producingfor a first time period, and then they are switched for a second timeperiod.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention.

EXAMPLES Comparative Example 1

A comparative example was conducted to show the effect of sodiumcarbonate on the formation of middle phase, type III, oil/watermicroemulsions at different brine concentrations when mixed with asurfactant and an isobutyl alcohol co-solvent.

As noted above, middle phase, type III, oil/water microemulsions exhibitvery low interfacial tension between oil and water, and the formation ofsuch microemulsions in an oil-bearing formation may enhance themobilization of the oil for production from the formation due toreduction of interfacial tension between oil and water in the formation,where the extent of mobilization may be relative to the extent thatinterfacial tension is reduced. The interfacial tension between oil andwater in which a middle phase, type III, microemulsion has formed issubstantially lower than oil and water in which little or nomicroemulsion has formed, and is also significantly lower than theinterfacial tension between oil and water in which a lower phase, typeI, microemulsion has formed (where the microemulsion is an oil-in-watermicroemulsion residing in a lower water phase with nearly pure oil in anupper phase) or in which an upper phase, type II, microemulsion hasformed (where the microemulsion is a water-in-oil microemulsion residingin an upper oil phase with nearly pure water in a lower phase). Theinterfacial tension of an aqueous surfactant system can be reliablyestimated by measuring the volumes of phases that form from oil andbrine at equilibrium. Ultra-low interfacial tension is evidenced by theformation of a third, middle (type III), microemulsion phase that existsbetween the oil phase and the water phase.

An oil recovery alkaline-surfactant solution was prepared by mixingsodium carbonate, a surfactant (PETROSTEP A-1, commercially availablefrom Stepan Company), isobutyl alcohol, and deionized water. Thesolution contained 1.5 wt. % sodium carbonate, 0.75 wt. % surfactant,and 1 wt. % isobutyl alcohol, where water formed the rest of thesolution. 10 samples containing 10 ml of this solution were prepared in20 ml test tubes. Sodium chloride was added to nine of the samples sothat the samples contained the amounts of sodium chloride shown in Table2:

TABLE 2 Sample # NaCl (wt. %) 1 0 2 0.1 3 0.2 4 0.3 5 0.4 6 0.5 7 0.6 80.7 9 0.8 10 0.910 ml of oil was added to each sample after dissolution of the sodiumchloride in the solution. The samples were then shaken and subsequentlystored at 70° C. for 1 hour. The samples were then shaken again and thenallowed to equilibrate. After equilibration, the samples were visuallyinspected to determine the phase behavior of the samples. Samples 5-7contained clearly visible middle phase microemulsions (type III). FIG. 5shows a photograph of the samples after equilibration. The oil recoverysolution containing sodium carbonate and a surfactant, therefore, wasshown to form middle phase microemulsions at favorable brineconcentrations, and would be useful to enhance oil recovery from asuitable oil-bearing formation by lowering the interfacial tensionbetween oil and water in the formation and thereby mobilizing the oilfor recovery.

Comparative Example 2

A comparative example was conducted to show the effect of ammoniumhydroxide on the formation of middle phase, type III, oil/watermicroemulsions at different brine concentrations when mixed with asurfactant and an isobutyl alcohol co-solvent. An oil recoveryalkaline-surfactant solution was prepared by mixing ammonium hydroxide,a surfactant (PETROSTEP A-1), isobutyl alcohol, and deionized water,where the ammonium hydroxide constituted 0.5 wt. % of the solution, thesurfactant constituted 0.5 wt. % of the solution, and the isobutylalcohol constituted 0.5 wt. % of the solution. 5 samples containing 10ml of this solution were prepared in 20 ml test tubes. Sodium chloridewas added to the samples so that the samples contained the amounts ofsodium chloride shown in Table 3:

TABLE 3 Sample # NaCl (wt. %) 1 1.25 2 1.50 3 1.75 4 2.00 5 2.2510 ml of oil was added to each sample after dissolution of the sodiumchloride in the solution. The samples were then shaken and subsequentlystored at 70° C. for 1 hour. The samples were then shaken again and thenallowed to equilibrate. After equilibration, the samples were visuallyinspected to determine the phase behavior of the samples. Sample 3contained a clearly visible middle phase microemulsion (type III). FIG.6 shows a photograph of the samples after equilibration. The oilrecovery solution containing ammonium hydroxide and a surfactant,therefore, was shown to form a middle phase microemulsion at favorablebrine concentrations, and would be useful to enhance oil recovery from asuitable oil-bearing formation by lowering the interfacial tensionbetween oil and water in the formation and thereby mobilizing the oilfor recovery.

Comparative Example 3

A comparative example was conducted to show the effect of calcium on theformation of middle phase, type III, oil/water microemulsions atdifferent brine concentrations of ammonium hydroxide mixed with asurfactant and an isobutyl alcohol co-solvent. The experiment conductedin Comparative Example 2 was repeated except that 1000 ppm of calciumion added as CaCl₂ (basis the oil recovery solution of ammoniumhydroxide, surfactant, isobutyl alcohol, and deionized water) was addedto the oil recovery solution together with sodium chloride.

Visual observation indicated that none of the samples contained avisible middle phase microemulsion, indicating that the presence ofcalcium interferes with the formation of a middle phase microemulsionwhen ammonium hydroxide is used as the alkaline component of analkaline/surfactant oil recovery formulation and may inhibit minimizingthe interfacial tension between oil and water. FIG. 7 shows a photographof the samples after equilibration.

ILLUSTRATIVE EXAMPLE

An illustrative example was conducted to show the effectiveness of analkaline surfactant solution containing ammonium hydroxide, sodiumcarbonate, a surfactant, isobutyl alcohol, and deionized water to formmiddle phase, type III, oil/water microemulsions at different brineconcentrations in the presence of calcium when mixed with oil.

A first oil recovery alkaline-surfactant solution was prepared by mixingsodium carbonate, a surfactant (PETROSTEP A-1), isobutyl alcohol, anddeionized water. The solution contained 1.5 wt. % sodium carbonate, 0.75wt. % of the surfactant, and 1 wt. % of isobutyl alcohol. 3 samplescontaining 10 ml of this solution were prepared in 20 ml test tubes.Sodium chloride was added to the samples so that one sample contained0.3 wt. % NaCl, one sample contained 0.4 wt. % NaCl, and one samplecontained 0.5 wt. % NaCl. 1000 ppm of calcium ion added as CaCl₂ wasadded to each of the samples.

A second oil recovery alkaline-surfactant solution was prepared bymixing ammonium hydroxide, a surfactant (PETROSTEP A-1), isobutylalcohol, and deionized water. The solution contained 0.5 wt. % ammoniumhydroxide, 0.75 wt. % of the surfactant, and 1 wt. % of isobutylalcohol. 3 samples containing 10 ml of this solution were prepared in 20ml test tubes. Sodium chloride was added to the samples so that onesample contained 1.7 wt. % NaCl, one sample contained 1.9 wt. % NaCl,and one sample contained 2.1 wt. % NaCl. 1000 ppm of calcium ion addedas CaCl₂ was added to each of the samples.

A third oil recovery alkaline-surfactant solution was prepared by mixingammonium hydroxide, sodium carbonate, a surfactant (PETROSTEP A-1),isobutyl alcohol, and deionized water. The solution contained 0.4 wt. %ammonium hydroxide (less than the second oil recoveryalkaline-surfactant solution), 0.4 wt. % sodium carbonate (substantiallyless than the first oil recovery alkaline-surfactant solution), 0.75 wt.% of the surfactant, and 1 wt. % of isobutyl alcohol. 3 samplescontaining 10 ml of this solution were prepared in 20 ml test tubes.Sodium chloride was added to the samples so that one sample contained1.3 wt. % NaCl, one sample contained 1.5 wt. % NaCl, and one samplecontained 1.7 wt. % NaCl. 1000 ppm calcium ion added as CaCl₂ was addedto each of the samples.

10 ml of oil was added to each sample of the first, second, and thirdoil recovery alkaline-surfactant solutions after addition of the sodiumchloride and calcium chloride thereto. The samples were then shaken andsubsequently stored at 70° C. for 1 hour. The samples were then shakenagain and then allowed to equilibrate. After equilibration, the sampleswere visually inspected to determine the phase behavior of the samples.A well-defined middle phase microemulsion was observed in the third oilrecovery alkaline surfactant solution containing both ammonium hydroxideand sodium carbonate in the sample containing 1.5 wt. % NaCl despite thepresence of CaCl₂ in the sample, indicating that the alkaline surfactantsolution containing ammonium hydroxide and sodium carbonatesignificantly lowered the interfacial tension between the oil and water,and may be useful for mobilizing oil in a formation for production fromthe formation under optimized salinity conditions. A similar middlephase microemulsion was observed in the first oil recovery alkalinesurfactant solution containing sodium carbonate without ammoniumhydroxide in the sample containing 0.4 wt. % NaCl, and no middle phasemicroemulsion was observed in any of the samples of the second oilrecovery alkaline surfactant solution containing ammonium hydroxidewithout sodium carbonate. FIG. 8 shows a photograph of the samples ofeach of the alkaline surfactant solutions after mixing with CaCl₂ andoil and subsequent equilibration.

This example demonstrated that a middle phase microemulsion can beformed with oil and water using an alkaline surfactant solutioncontaining ammonium hydroxide and sodium carbonate as alkalinecomponents.

The present invention is well adapted to attain the ends and advantagesmentioned as well as those that are inherent therein. The particularembodiments disclosed above are illustrative only, as the presentinvention may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. While systems and methods are described in terms of“comprising,” “containing,” or “including” various components or steps,the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. Whenever a numericalrange with a lower limit and an upper limit is disclosed, any number andany included range falling within the range is specifically disclosed.In particular, every range of values (of the form, “from a to b,” or,equivalently, “from a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Whenever a numerical range having a specific lower limit only, aspecific upper limit only, or a specific upper limit and a specificlower limit is disclosed, the range also includes any numerical value“about” the specified lower limit and/or the specified upper limit.Also, the terms in the claims have their plain, ordinary meaning unlessotherwise explicitly and clearly defined by the patentee. Moreover, theindefinite articles “a” or “an”, as used in the claims, are definedherein to mean one or more than one of the element that it introduces.

What is claimed is:
 1. A process for recovering oil from an oil-bearingformation, comprising: mixing a surfactant, water, a polymer, an alkalimetal carbonate or an alkali metal bicarbonate, and an ammonia liquid toform an oil recovery formulation; introducing the oil recoveryformulation into the oil-bearing formation; contacting the oil recoveryformulation with oil in the oil-bearing formation; and producing oilfrom the oil-bearing formation after introduction of the oil recoveryformulation into the oil-bearing formation.
 2. The process of claim 1wherein the amount of ammonia liquid mixed with the surfactant, thepolymer, the alkali metal carbonate or alkali metal bicarbonate, and thewater is selected to comprise from 0.01 wt. % to 5 wt. % of the totalweight of the oil recovery formulation and the amount of alkali metalcarbonate or alkali metal bicarbonate mixed with the surfactant, water,the polymer, and the ammonia liquid is selected to comprise from 0.001wt. % to 1 wt. % of the total weight of the oil recovery formulation. 3.The process of claim 1 wherein the ammonia liquid is anhydrous liquidammonia and the alkali metal carbonate is sodium carbonate.
 4. Theprocess of claim 1, further comprising the steps of: calculating theminimum quantity of alkali metal carbonate or alkali metal bicarbonaterequired to precipitate 100% of the estimated amount of calcium cationson clay mineral sites in the formation; limiting the amount of alkalimetal carbonate or alkali metal bicarbonate mixed with the surfactant,water, polymer, and ammonia liquid to at most 10 times the calculatedminimum quantity of alkali metal carbonate or alkali metal bicarbonate.5. The process of claim 1, wherein the surfactant is an anionicsurfactant selected from the group consisting of an alpha olefinsulfonate compound, an internal olefin sulfonate compound, a branchedalkyl benzene sulfonate compound, a propylene oxide sulfate compound, anethylene-propylene oxide sulfate compound, or a blend thereof.
 6. Theprocess of claim 1 wherein the polymer is selected from the groupconsisting of polyacrylamides; partially hydrolyzed polyacrylamides;copolymers of acrylamide, acrylic acid, AMPS (2-acrylamide-, methylpropane sulfonate) and n-vinylpyrrolidone in any ratio; polyacrylates;ethylenic co-polymers; biopolymers; carboxymethylcelloluses; polyvinylalcohols; polystyrene sulfonates; polyvinylpyrrolidones; AMPS; andcombinations thereof.
 7. The process of claim 1 wherein the oil recoveryformulation comprises from 0.05 wt. % to 5 wt. % of the surfactant, from200 ppm to 10000 ppm of the polymer, from 0.01 wt. % to 5 wt. % of theammonia liquid, and from 0.001 wt. % to 1 wt % of the alkali metalcarbonate or alkali metal bicarbonate.
 8. The process of claim 1 whereinthe oil-bearing formation is a subterranean formation having a calciumion exchange capacity of at least 0.25 meq/100 grams and a temperatureof at least 60° C.
 9. The process of claim 1 wherein the oil-bearingformation is a subsea formation.
 10. The process of claim 1 wherein theoil recovery formulation has a dynamic viscosity within 50% of thedynamic viscosity of oil of the oil-bearing formation when measuredisothermally at a formation temperature.
 11. A composition comprising amixture of a surfactant, a polymer, ammonia, water, and an alkali metalcarbonate or an alkali metal bicarbonate.
 12. The composition of claim11 wherein the ammonia comprises from 0.01 wt. % to 5 wt. % of thecomposition and the alkali metal carbonate or alkali metal bicarbonatecomprises from 0.001 wt. % to 1 wt. % of the composition.
 13. Thecomposition of claim 11 wherein the surfactant is an anionic surfactant.14. The composition of claim 11 wherein the polymer is selected from thegroup consisting of polyacrylamides; partially hydrolyzedpolyacrylamides; copolymers of acrylamide, acrylic acid, AMPS(2-acrylamide-methyl propane sulfonate) and n-vinylpyrrolidone in anyratio; polyacrylates; ethylenic co-polymers; biopolymers;carboxymethylcelloluses; polyvinyl alcohols; polystyrene sulfonates;polyvinylpyrrolidones; AMPS; and combinations thereof.
 15. Thecomposition of claim 11 wherein the composition comprises from 0.05 wt.% to 5 wt. % of the surfactant, from 200 ppm to 10000 ppm of thepolymer, from 0.01 wt. % to 5 wt. % of the ammonia, and from 0.001 wt. %to 1 wt. % of the alkali metal carbonate or alkali metal bicarbonate.16. A system, comprising: a surfactant; a polymer; an ammonia liquid; analkali metal carbonate or an alkali metal bicarbonate; water; anoil-bearing formation; a mechanism for introducing the surfactant, thepolymer, the alkali metal carbonate or alkali metal bicarbonate, theammonia liquid and the water into the oil-bearing formation; and amechanism for producing oil from the oil-bearing formation subsequent tointroduction of the surfactant, the polymer, the alkali metal carbonateor alkali metal bicarbonate, the ammonia liquid and the water into theoil-bearing formation.
 17. The system of claim 16 further comprising amechanism for mixing the surfactant, the polymer, the alkali metalcarbonate or alkali metal bicarbonate, the ammonia liquid, and the waterto form an oil recovery formulation, wherein the mechanism forintroducing the surfactant, the polymer, the alkali metal carbonate oralkali metal bicarbonate, the ammonia liquid, and the water into theoil-bearing formation is a mechanism for introducing the oil recoveryformulation into the oil-bearing formation.
 18. The system of claim 17wherein the oil recovery formulation comprises from 0.01 wt. % to 5 wt.% of the ammonia liquid and from 0.001 wt. % to 1 wt. % of the alkalimetal carbonate or alkali metal bicarbonate.
 19. The system of claim 16wherein the oil-bearing formation is a subsea formation.
 20. The systemof claim 19 further comprising: a platform located on the surface of asea located above the subsea formation; a storage facility for storingthe surfactant located on the platform; a storage facility for storingthe polymer located on the platform; a storage facility for storing thealkali metal carbonate or alkali metal bicarbonate located on theplatform; and a storage facility for storing the ammonia liquid locatedon the platform.
 21. The system of claim 16 wherein at least a portionof the oil-bearing formation has a temperature of at least 60° C. 22.The system of claim 16 wherein the ammonia liquid is anhydrous liquidammonia and the alkali metal carbonate is sodium carbonate.
 23. Aprocess for recovering oil from an oil-bearing formation, comprising:introducing a surfactant, water, a polymer, an alkali metal carbonate oralkali metal bicarbonate, and an ammonia liquid into the oil-bearingformation; mixing the surfactant, water, polymer, alkali metal carbonateor alkali metal bicarbonate, and ammonia liquid in the oil-bearingformation to form an oil recovery formulation; contacting the oilrecovery formulation with oil in the oil-bearing formation; andproducing oil from the oil bearing-formation after contacting the oilrecovery formulation with oil in the oil-bearing formation.
 24. Theprocess of claim 23 wherein the amount of ammonia liquid introduced intothe formation is from 0.01 wt. % to 5 wt. % of the total combined weightof the ammonia liquid, the water, the surfactant, the alkali metalcarbonate or alkali metal bicarbonate, and the polymer introduced intothe formation and the amount of alkali metal carbonate or alkali metalbicarbonate introduced into the formation is from 0.001 wt. % to 1 wt. %of the total combined weight of the ammonia liquid, the water, thesurfactant, the alkali metal carbonate or alkali metal bicarbonate, andthe polymer introduced into the formation.
 25. The process of claim 23wherein the ammonia liquid is liquid anhydrous ammonia and the alkalimetal carbonate is sodium carbonate.
 26. The process of claim 23 whereinthe water has a total dissolved solids content of from 200 ppm to 100000ppm.
 27. The process of claim 23 wherein the surfactant is an anionicsurfactant selected from the group consisting of an alpha olefinsulfonate compound, an internal olefin sulfonate compound, a branchedalkyl benzene sulfonate compound, a propylene oxide sulfate compound, anethylene-propylene oxide sulfate compound, or a blend thereof.
 28. Theprocess of claim 23 wherein the polymer is selected from the groupconsisting of polyacrylamides; partially hydrolyzed polyacrylamides;copolymers of acrylamide, acrylic acid, AMPS (2-acrylamide-, methylpropane sulfonate) and n-vinylpyrrolidone in any ratio; polyacrylates;ethylenic co-polymers; biopolymers; carboxymethylcelloluses; polyvinylalcohols; polystyrene sulfonates; polyvinylpyrrolidones; AMPS; andcombinations thereof.
 29. The process of claim 23 wherein the oilrecovery formulation comprises from 0.05 wt. % to 5 wt. % of thesurfactant, from 200 ppm to 10000 ppm of the polymer, from 0.001 wt. %to 1 wt. % of the alkali metal carbonate or alkali metal bicarbonate,and from 0.01 wt. % to 5 wt. % of the ammonia liquid.
 30. The process ofclaim 23 wherein the oil-bearing formation is a subterranean formationwherein at least a portion of the formation has a temperature of atleast 60° C.
 31. The process of claim 23 wherein the oil-bearingformation is a subsea formation.